Accurate permeability prediction in tight gas rocks via lattice Boltzmann simulations with an improved boundary condition

Fan, Dian; Phan, Anh; Striolo, Alberto

doi:10.1016/j.jngse.2019.103049

Cited by 9 publications

(3 citation statements)

References 75 publications

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“…Thus, for more general situations of fluid transport in microporous/nanoporous shale, upscale strategies are needed to extend molecular simulations to pore-scale simulations. Generally, the upscale strategies still rely on the conventional simulation methods for porous media, which can automatically address the complex flow in porous structure and the primary mission of MD simulations is coupling nanoscale flow characteristic. − In light of such tactics, some MD-based lattice Boltzmann method (LBM) and pore network model (PNM) simulations are proposed for pore-scale transport in a shale matrix, which would be individually expounded in the following sections.…”

Section: Pore-scale Simulationsmentioning

confidence: 99%

Transport of Shale Gas in Microporous/Nanoporous Media: Molecular to Pore-Scale Simulations

Fan

et al. 2020

Energy Fuels

136

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As the typical unconventional reservoir, shale gas is believed to be the most promising alternative for the conventional resources in future energy patterns, attracting more and more attention throughout the world. Generally, the majority of shale gas is trapped within the tight shale rock with ultralow porosity (<10%) and ultrasmall pore size (as less as several nanometers). Thus, the accurate understanding of gas transport characteristic and its underlying mechanism through these microporous/nanoporous media is critical for the effective exploitation of shale reservoir. In this context, we present a comprehensive review on the current advances of multiscale transport simulations of shale gas in microporous/nanoporous media from molecular to pore-scale. For the gas transport in shale nanopores using molecular dynamics (MD) simulations, the structure and force parameters of various nanopore models, including organic models (graphene, carbon nanotubes, and kerogen) and inorganic models (clays, carbonate, and quartz), and flow simulation strategies (such as nonequilibrium molecular dynamics (NEMD) and Grand Canonical Monte Carlo simulations) are systematically introduced and clarified. The significant MD simulation results about gas transport characteristic in shale nanopores then are elaborated respectively for different factors, including pore size, ambient pressure, nanopore type, atomistic roughness, and pore structure, as well as multicomponent. Besides, the two-phase transport characteristic of gas and water is also discussed, considering the ubiquity of water in shale formation. For the lattice Boltzmann method (LBM) and pore network model (PNM) approaches to conduct pore-scale simulations, we briefly review its origins, modifications, and applications for gas transport simulations in a microporous/nanoporous shale matrix. Particularly, the upscaling methods to incorporate MD simulation into LBM and PNM frameworks are emphatically expounded in the light of recent attempts of MD-based pore-scale simulations. It is hoped that this Review would be helpful for the readers to build a systematical overview on the transport characteristic of shale gas in microporous/nanoporous media and subsequently accelerate the development of the shale industry.

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Section: Pore-scale Simulationsmentioning

confidence: 99%

Transport of Shale Gas in Microporous/Nanoporous Media: Molecular to Pore-Scale Simulations

Fan

et al. 2020

Energy Fuels

136

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“…Either of these factors increases the dimensionless Knudsen number (Kn), defined as a ratio of the mean free path ( ) of the gas to the average pore diameter ( d p ). With the increase of Kn, the gas flow becomes more rarefied and transitions from slip flow to transitional flow, and eventually to the free molecular flow (Darabi et al 2012;Fan et al 2020;Javadpour and Ettehadtavakkol 2015;Fan and Ettehadtavakkol 2017b).…”

Section: The Alp Versus Klinkenberg Equationmentioning

confidence: 99%

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

2020

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Apparent liquid permeability (ALP) in ultra-confined permeable media is primarily governed by the pore confinement and fluid–rock interactions. A new ALP model is required to predict the interactive effect of the above two on the flow in mixed-wet, heterogeneous nanoporous media. This study derives an ALP model and integrates the compiled results from molecular dynamics (MD) simulations, scanning electron microscopy, atomic force microscopy, and mercury injection capillary pressure. The ALP model assumes viscous forces, capillary forces, and liquid slippage in tortuous, rough pore throats. Predictions of the slippage of water and octane are validated against MD data reported in the literature. In up-scaling the proposed liquid transport model to the representative-elementary-volume scale, we integrate the geological fractals of the shale rock samples including their pore size distribution, pore throat tortuosity, and pore-surface roughness. Sensitivity results for the ALP indicate that when the pore size is below 100 nm pore confinement allows oil to slip in both hydrophobic and hydrophilic pores, yet it also restricts the ALP due to the restricted intrinsic permeability. The ALP reduces to the well-established Carman–Kozeny equation for no-slip viscous flow in a bundle of capillaries, which reveals a distinguishable liquid flow behavior in shales versus conventional rocks. Compared to the Klinkenberg equation, the proposed ALP model reveals an important insight into the similarities and differences between liquid versus gas flow in shales.

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“…Either of these factors increases the dimensionless Knudsen number (Kn). With the increase of the Knudsen, gas flow becomes more rarefied and transits from slip flow to transitional flow, and eventually to the free molecular flow [42,19,27].…”

Section: The Alp Versus Klinkenberg Equationmentioning

confidence: 99%

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

Fan,

Ettehadtavakkol,

Wang

2020

Preprint

Self Cite

View full text Add to dashboard Cite

Apparent liquid permeability (ALP) in ultra-confined permeable media is primarily governed by the pore confinement and rock-fluid interactions. A new ALP model is required to predict the interactive effect of the above two on the flow in mixed-wet, heterogeneous nanoporous media. This study derives an ALP model and integrates the compiled results from molecular dynamics (MD) simulations, scanning electron microscopy, atomic force microscopy, and mercury injection capillary pressure. The ALP model assumes viscous forces, capillary forces, and liquid slippage in tortuous, rough pore throats. Predictions of the slippage of water and octane are validated against MD data in the literature. In up-scaling the proposed liquid transport model to the representative-elementary-volume scale, we integrate the geological fractals of the shale rock samples including their pore size distribution, pore-throat tortuosity, and pore-surface roughness.Sensitivity results for the ALP indicate that when the pore size is below 100 nm strong pore confinement allows oil to slip in both hydrophobic and hydrophilic pores, yet it restricts the ALP due to the low intrinsic permeability. The ALP reduces to the well-established Carman-Kozeny equation for no-slip viscous flow in a bundle of capillaries, which reveals a distinguishable liquid flow behavior in shales versus conventional rocks. Compared to the Klinkenberg equation, the proposed ALP model reveals an important insight to the similarities and differences between liquid versus gas flow in shales.

show abstract

Accurate permeability prediction in tight gas rocks via lattice Boltzmann simulations with an improved boundary condition

Cited by 9 publications

References 75 publications

Transport of Shale Gas in Microporous/Nanoporous Media: Molecular to Pore-Scale Simulations

Transport of Shale Gas in Microporous/Nanoporous Media: Molecular to Pore-Scale Simulations

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

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